1. Field of the Invention
The present invention generally relates to the field of oil and gas production and, more particularly, to a system and method for the in situ determination of the distribution and orientation of natural fractures in subterranean formations.
2. Discussion of the Related Art
Planar flaws such as faults, fractures, joints, etc., exist in abundance in all subterranean rock formations. With the exception of certain sets found in so-called "naturally fractured" formations, most of these flaws remain closed under the conditions imposed by the in situ stress state. However, perturbations of this state, such as those caused by fluid injection, will result in renewed movement on those flaw sets which are favorably oriented with respect to the principal axes of the perturbed stress state. Theoretical studies predict that these movements will be characterized by both a deviatoric component (relative movement parallel to the fracture face) as well as a dilatant component (relative movement perpendicular to the fracture face) depending upon the orientation of the fracture with respect to the principal axes of the local stress state as well as upon the relative magnitude of these stresses. Dilatant movement on a given fracture will enhance its fluid conductivity relative to that of the surrounding matrix. Consequently, fluid flow will proceed in directions defined by the orientation and distribution of those fracture sets which are not only activated by the injection process but are also characterized by a significant dilatational component of relative movement. Therefore, in order to maximize the efficiency of fluid injection projects such as waterfloods and to aid in the resolution of fluid leak-off problems associated with hydraulic fracturing treatments, it is important not only to determine the orientation of the fractures activated by the injection process, but also to determine their capacity for dilatant movement under the conditions imposed by the existing stress state.
At the present time, data concerning the distribution and orientation of natural fractures is typically acquired from the analysis of oriented core data. This method has the following disadvantages:
It samples only a small fraction of the reservoir. PA1 It undersamples the density of fractures whose dips are approximately normal to the axis of the core. PA1 It undersamples the density of fractures whose dimensions are much larger than the core dimensions.
In order to compensate for these problems, data provided by cross-well seismic surveys has occasionally been used to supplement the core data. However, cross-well seismics will only detect fractures whose dimensions are greater than a few meters and then only if there is a significant contrast in elastic properties of the rock matrix across the fracture face. Geologic studies of reservoir outcrops have also been used to address this problem. However, there may be no accessible outcrops of the reservoir rock. Even if such outcrops exist, there is no guarantee that the fracture distribution observed at the surface is representative of the distribution in the production zone. Neither of these techniques listed above will identify those fracture sets which are likely to be activated by the injection process and they provide no information concerning the dilatant properties of the observed fracture sets.
Attempts have also been made to put seismic sensors in reservoirs for relatively long periods of time, to detect the induced microseismic activity and map the spatial continuity of the sources of such activity using standard microseismic analysis techniques. While this method will identify the fractures activated by the injection process, it provides no information about the orientation and dilatant behavior of the fractures and is time consuming and costly to implement. Thus, there is a need for a method which will not only identify fracture sets activated by fluid injection, but also discriminate between deviatoric and dilatant fracture trends in a timely and cost effective manner.
It is well known that the amplitudes of seismic waves are functionally dependent, not only upon the strength of the source, and the length of the ray-path between source and observation point, but also upon the orientation of the source fracture, the orientation of its slip direction, and the orientation of the ray path at its point of origin. Thus, augmentation of standard microseismic data processing procedures to include the processing and analysis of the P and S wave amplitude data will provide estimates of the orientation of the source fractures and their slip directions. While the combined output of both the standard microseismic analysis and fracture orientation processing procedures will discriminate between deviatoric and dilatant fracture trends activated by the injection process.
Standard microseismic analysis techniques locate the sources of the microseismic activity induced by fluid injection. There are two basic methods for the accomplishment of this task. If several sensors at widely distributed locations are available, then generalized triangulation techniques should be used to determine microseismic source locations. Generalized triangulation, requires the measurement of the initial arrival times of the elastic waves generated by the source at the distributed observation points, as well as an independently acquired model of the seismic wave velocity distributions between the source and the observations points. Generalized triangulation can provide highly accurate source locations under ideal circumstances. However, for most typical oil and gas applications, such as hydraulic fracturing, ideal circumstances are rarely attainable. The essential problem is that the strengths of the induced microseismic sources are relatively weak and their associated elastic waves are not usually detectable at ranges in excess of 1000-2000 feet. Since most oil and gas production is derived from formations at depths greater than 1000-2000 feet, it is generally not feasible to attempt to detect induced microseismic activity with sensors deployed on the earth's surface. Thus, microseismic sensor systems deployed to monitor oil and gas well stimulation or production processes must typically be placed in nearby offset wells or in the injection well itself. When only one observation well is available, distribution of the sensors is restricted and the generalized triangulation technique becomes ineffective.
Since the cost of furnishing more than one well for microseismic observations is usually prohibitive to the producer, a second method of microseismic source location has evolved for oil and gas well monitoring applications. This method is implemented by measuring the arrival times of the compressional waves (P waves) and shear waves (S waves) as well as the particle motion of the P wave with orthogonally oriented, three component sensors deployed at one or more points in the observation well. Then, assuming that the elastic wave velocity distributions in the rock formations are known, the distances between the sources and the observation points may be determined from the differences between the arrival times of the P and S waves; while the directions from the observation points to the sources may be inferred from the orientation of the P wave particle motion. Fairly precise source locations can be obtained through the application of this method when data are available from 4 or more observation points and the distance between source and observation points is less than 1000-2000 feet.
The system and method of the present invention was developed specifically to augment this latter standard microseismic analysis technique so that it is particularly well suited for applications to microseismic data acquired in a single observation well. The present invention measures, then determines the ratio of the amplitudes of the shear and compressional waves detected at multiple points in one or more observation wells for each source fracture. It then uses a forward modeling method which compares these ratios to theoretical values to determine the orientation of a vector normal to the source fracture plane and a vector parallel to the direction of relative movement of the two surfaces of the source fracture plane. The dilatant behavior of the source fracture, if any, is then determined by comparison of the orientation of these two vectors.